There are many subterranean tar sand deposits throughout the world which contain high viscosity heavy oil. The vast Athabasca and Cold lake deposits in Alberta, Canada represent some of the most notable examples of such formations.
A variety of methods have been proposed for recovering hydrocarbons from these formations by increasing the mobility of the oil. Such methods include thermal stimulation processes including a Cyclic Steam Simulation (CSS) process, a Steam Flood (SF) process and a Steam Assisted Gravity Drainage (SAGD) process. Generally speaking, these processes use steam to heat and mobilize the oil, and then the mobilized oil is recovered using a production well.
In the CSS process, steam is injected through an injection well into the hydrocarbon-bearing formation. The well is shut-in so that the steam soaks in and heat is transferred to the formation to lower the viscosity of the hydrocarbon. In the production phase, oil is pumped from the formation using the same wellbore. Several cycles of steam injection and hydrocarbon production are continued until production becomes too low to justify further steam injection.
The SF process involves injecting steam into the formation through an injection well. Steam moves through the formation, mobilizing oil as it flows toward the production well. Mobilized oil is swept to the production well by the steam drive.
The SAGD process involves injecting steam into the formation through an injection well or wells at a rate which is able to maintain a near constant operating pressure in the steam chamber. Steam at the edges of the steam chamber condenses as it heats the adjacent non-depleted formation. The mobilized oil and steam condensate flow via gravity to a separate production well located at the base of the steam chamber.
One concern in all thermal stimulation processes is the distribution of steam from horizontal wells into the formation. This is accomplished in conventional techniques by providing holes or slots in the casing. In a horizontal well which is used only for steam injection at subfracture reservoir pressures, uniform steam distribution can be achieved by two means--the number and size of holes in the liner can be limited, such that at the desired steam injection rates, critical (sonic) flow is achieved through the holes and equitable steam distribution at each hole location is achieved; or the target steam injection rates can be constrained such that only a minimal pressure drop occurs along the liner. Thus, the pressure gradient available for steam flow between the liner and reservoir at all points on the horizontal well are essentially the same. Both of these design criteria put significant constraints on the steam injection operation. Designing for critical flows means that the peak injection rates are capped. Designing a liner to achieve minimal pressure drops severely restricts the maximum steam injection rates, maximum liner length and minimum liner diameter which can be utilized. Again, this means that the peak injection rates are capped.
In a horizontal well which is used for steam injection at fracture pressures, neither of these steam distribution techniques is adequate. In a reservoir such as the Clearwater formation at Cold Lake, the reservoir fracture pressure is typically 10 to 11 MPa. This pressure is too high to allow the critical flow design option to be successfully utilized. If a conventional liner were used, it is most likely the horizontal well would fracture at only one location along the wellbore, and, in the following steam cycle, it may not be possible to move the fracture to a different portion of the wellbore.
If a steam injection well is also used for oil production, particulate matter (such as sand and other formation fines) can either plug the holes or slots directly if relatively few openings are available, or they can also flow into the well with the produced hydrocarbons. Particulate matter settling inside the well can choke off sections of the well completely, thereby adversely affecting hydrocarbon production and steam injection in the following cycles.
In an effort to minimize the production of particulate matter with hydrocarbon fluids, well casings are often provided with a slotted liner or an external wire-wrap screen extending over a portion of the length of the horizontal portion of the well. Such liners and screens are available from Site Oil Tools Inc, Bonneyville, Alberta, Canada. In wire-wrap applications, holes are drilled in the well casing below the wire-wrap screens to provide an open area of about 8%. To achieve this degree of open area, hundreds of 3/8 in (0.95 cm) diameter holes are required. For example, for a typical 85/8 in (21.9 cm) diameter pipe, 2463/8 in (0.95 cm) holes are required per foot length of pipe to give an open area of 8.4%. The ratio of screened to blank sections of pipe is determined by the average % open area one wants for the application. Typically, the ratio is set to allow 1.5 to 3% of the base pipe to be open area. This relatively large open area is provided to minimize pressure drop constraints on and velocities of the fluids being produced from the reservoir. An external wire-wrap screen is then placed around the casing to reduce the flow of particulate matter through the holes. Slotted liners typically have corresponding open areas provided with the slots cut into the liner. In these designs, essentially no flow restrictions occur as the fluids pass through the slots or wire-wrap screen assemblies. Corresponding high velocities may expose the liner to erosion by the entrained sand.
An example of known techniques for distributing steam is described in U.S. Pat. No. 5,141,054 (Mobil), which relates to a limited entry steam heating method for distributing steam from a closed-end tubing in a perforated well casing. The tubing string has perforations to achieve critical flow conditions such that the steam velocity through the holes in the close-end tubing reach acoustic speed. However, due to the large annulus flow area, plus the still large number of holes in the well casing, critical flow is not maintained in the wellbore annulus and through the casing into the reservoir, so that the desired steam distribution control is lost.
It is an object of the present invention to provide a system and method for distributing steam and producing hydrocarbons from the same well.
It is another object of the present invention to enhance steam distribution during a thermal stimulation phase, and to reduce the influx of particulate matter during a production phase, for a well.
It is a further object of the present invention to provide a system and method where steam injection may occur at pressures below, up to, or exceeding the reservoir fracture pressure.